WO2015112297A1 - Procédé de re-fracturation au moyen de gomme de galactomannane borée - Google Patents

Procédé de re-fracturation au moyen de gomme de galactomannane borée Download PDF

Info

Publication number
WO2015112297A1
WO2015112297A1 PCT/US2014/071566 US2014071566W WO2015112297A1 WO 2015112297 A1 WO2015112297 A1 WO 2015112297A1 US 2014071566 W US2014071566 W US 2014071566W WO 2015112297 A1 WO2015112297 A1 WO 2015112297A1
Authority
WO
WIPO (PCT)
Prior art keywords
well
zone
productive zone
fracturing
fluid
Prior art date
Application number
PCT/US2014/071566
Other languages
English (en)
Inventor
D.V. Satyanarayana Gupta
Original Assignee
Baker Hughes Incorporated
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from US14/165,427 external-priority patent/US9920609B2/en
Application filed by Baker Hughes Incorporated filed Critical Baker Hughes Incorporated
Priority to CN201480074326.7A priority Critical patent/CN106133111A/zh
Priority to CA2938037A priority patent/CA2938037C/fr
Priority to RU2016134934A priority patent/RU2682833C2/ru
Publication of WO2015112297A1 publication Critical patent/WO2015112297A1/fr

Links

Classifications

    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
    • C09K8/426—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells for plugging
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • C—CHEMISTRY; METALLURGY
    • C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
    • C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
    • C04B26/00—Compositions of mortars, concrete or artificial stone, containing only organic binders, e.g. polymer or resin concrete
    • C04B26/02—Macromolecular compounds
    • C04B26/28—Polysaccharides or derivatives thereof
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
    • C09K8/44—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing organic binders only
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/504—Compositions based on water or polar solvents
    • C09K8/506—Compositions based on water or polar solvents containing organic compounds
    • C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • C09K8/512—Compositions based on water or polar solvents containing organic compounds macromolecular compounds containing cross-linking agents
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/504—Compositions based on water or polar solvents
    • C09K8/506—Compositions based on water or polar solvents containing organic compounds
    • C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • C09K8/514—Compositions based on water or polar solvents containing organic compounds macromolecular compounds of natural origin, e.g. polysaccharides, cellulose
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/84—Compositions based on water or polar solvents
    • C09K8/86—Compositions based on water or polar solvents containing organic compounds
    • C09K8/88—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • C09K8/887—Compositions based on water or polar solvents containing organic compounds macromolecular compounds containing cross-linking agents
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/84—Compositions based on water or polar solvents
    • C09K8/86—Compositions based on water or polar solvents containing organic compounds
    • C09K8/88—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • C09K8/90—Compositions based on water or polar solvents containing organic compounds macromolecular compounds of natural origin, e.g. polysaccharides, cellulose
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E21B43/261—Separate steps of (1) cementing, plugging or consolidating and (2) fracturing or attacking the formation
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
    • C09K2208/24—Bacteria or enzyme containing gel breakers
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
    • C09K2208/26—Gel breakers other than bacteria or enzymes

Definitions

  • the invention relates to the use of a well treatment fluid containing borated galactomannan gum as a temporary seal to effectuate zonal isolation between intervals of a wellbore as well as an alternative to cement.
  • the invention further relates to a method of re-fracturing a subterranean formation wherein the temporary seal is removed from the well by exposing the temporary seal to a viscosity reducing agent.
  • a subterranean formation penetrated by a well has a plurality of distinct zones or formations of interest.
  • Selective stimulation (such as by hydraulic fracturing and acid stimulation) becomes pronounced as the life of the well declines and productivity of the well decreases.
  • the fracturing fluid was then pumped into the well under pressure exceeding the pressure at which the zone and/or formations would fracture, in order to prevent the fracturing fluid from flowing into zones having greater porosity and/or lower pressure, a mechanical device, such as a straddle packer, or plug or sand fill was first set in the well between the zone just fractured and the zone to be fractured to isolate the stimulated zone from further contact with the fracturing fluid. This procedure was repeated until all of the zones of interest were perforated and fractured.
  • a mechanical device such as a straddle packer, or plug or sand fill was first set in the well between the zone just fractured and the zone to be fractured to isolate the stimulated zone from further contact with the fracturing fluid. This procedure was repeated until all of the zones of interest were perforated and fractured.
  • each plug had to be dri lled out of or otherwise removed from the well to permit fluid to be produced to the surface through the well.
  • the necessity of tripping in and out of the wellbore to perforate and stimulate each of the multiple zones and the use of such plugs to isolated previously treated zones and/or formations from further treatment fluid contact was both time consuming and expensive.
  • isolation assemblies have been reported to provide zonal isolation and which allow for selected treatment of productive (or previously producing intervals) in multiple interval wel!bores.
  • U.S. Patent No. 6386,288 discloses a mechanical zonal isolation system which may be provided on the outside of the casing string (cemented to the wellbore) to permit an interval of the formation to be completed and stimulated and/or treated independent of the others. In this manner, selected intervals of the subterranean formation may be stimulated and/or treated.
  • Such assemblies may include the use of flapper valve assemblies positioned between perforating gum assemblies.
  • the well treatment fluid described herein provides isolation during completion of a well and may be removed after or during post job flow-back.
  • the well treatment fluid defined herein is capable of leaving the face of the formation virtually damage free after post fracturing production.
  • the well treatment fluid contains a borated galactomannan gum, crosslinking agent and preferably a breaker.
  • the borated galactomannan prior to being cured or hardened with the crosslinking agent, contains borate ions.
  • the borated polygalactomannan may be pumped into a well which penetrates a formation unhydrated in water as a powder or as a hydrocarbon slurry.
  • Preferred galactomannans are guar gum and its derivatives, such as carboxymethyl ether derivatives and hydroxyalkyl ether derivatives.
  • underivatized guar may also be preferred.
  • Hydration of the well treatment fluid may be controlled by adjusting the pH and/or a crosslinking agent, such as a heat delayed crosslinking agent.
  • a crosslinking agent such as a heat delayed crosslinking agent.
  • hydration of the well treatment fluid may be delayed until the fluid reaches its downhole destination.
  • the well treatment fluid can therefore be effectively placed for preferentially sealing or blocking productive zones in the formation since delayed hydration of the fluid may be controlled for up to several hours.
  • the fluids are especially useful in the treatment of formations having multiple productive zones.
  • the well to be treated contains a zonal isolation system in the zone of interest.
  • the treatment fluid may be used in vertical as well as non-vertical wells. In such instances, the well may be perforated and then fractured without the use of any cement.
  • a method of enhancing the productivity of a formation penetrated by a well wherein an unhydrated borated galactomannan gum and a crosslinking agent is pumped into the well.
  • the unhydrated borated galactomannan gum contains borate ions prior to being crosslinked or cured.
  • a method of enhancing the productivity of a hydrocarbon-bearing formation penetrated by a well having multiple productive zones is provided.
  • an unhydrated borated galactomannan gum and a crosslinking agent are introduced near a pre-determined productive zone of the well; the borate ions being incorporated into the unhydrated borated galactomannan gum prior to being crosslinked.
  • the pre-determined productive zone is isolated from the other zones of the well by hardening the well treatment fluid.
  • the isolated predetermined productive zone is then perforated.
  • the perforated pre-determined productive zone of the well is then hydraulically fractured by introducing into the perforated pre-determined productive zone a fracturing fluid at a pressure sufficient to fracture the perforated pre-determined productive zone.
  • a method of enhancing the productivity of a hydrocarbon-bearing formation penetrated by a cemented vertical well having a casing and multiple productive zones is disclosed.
  • the productive zone of the well is perforated.
  • the perforated productive zone is then subjected to hydraulic fracturing by introducing into the perforated productive zone a fracturing fluid at a pressure sufficient to fracture the perforated productive zone.
  • a well treatment fluid containing borated galactomannan gum and a crosslinking agent is then introduced into the casing above the fractured perforated productive zone; the borated galactomannan gum containing incorporated borate ions prior to being crosslinked.
  • the treatment fluid is then hardened.
  • a method of enhancing the productivity of a hydrocarbon-bearing subterranean formation is provided.
  • a well treatment fluid comprising an unhydrated borated guar and a crosslinking agent is introduced into an annulus between a wall of the wellbore and a pipe string disposed in the wellbore.
  • the pipe string has disposed therein a zonal isolation assembly.
  • the unhydrated borated guar prior to being crosslinked, contains incorporated borate ions.
  • the well treatment fluid is then hardened and a productive zone within the formation is isolated.
  • the isolated productive zone is then perforated within the zonal isolation assembly.
  • the isolated productive zone is then subjected to hydraulic fracturing by introducing into the zone a fracturing fluid at a pressure sufficient to fracture the isolated productive zone.
  • a method of enhancing the productivity of a hydrocarbon-bearing subterranean formation penetrated by a non- vertical well is disclosed.
  • a first packer is introduced into the well.
  • a zonal isolation assembly unit is introduced into the well adjacent to the first packer.
  • a second packer is then introduced into the well until the area defined by the zonal isolation assembly unit is defined by first packer and the second packer.
  • An unhydrated borated guar and a crosslinking agent is then introduced into the well.
  • the unhydrated borated guar is then hardened.
  • the unhydrated borate guar contains borate ions prior to hardening.
  • the area defined by the first packer and second packer is then sealed from other areas of the well.
  • the isolated zone is then subjected to hydraulic fracturing by introducing into the zone a fracturing fluid at a pressure sufficient to fracture the isolated zone. These steps may be repeated in another area of the well.
  • a method of re-fracturing a subterranean formation penetrated by a well is provided.
  • a viscosity reducing agent is pumped into the well.
  • the viscosity of a gelled temporary seal is then reduced.
  • the gelled temporary seal is a product of an unhydrated borated galactomannan gum and a crosslinking agent.
  • the viscosity reducing agent is pumped into the well at a pressure insufficient to create or enlarge a fracture within the subterranean formation.
  • a fracturing fluid is then pumped into the well at a pressure sufficient to create or enlarge a fracture within a pre-determined productive zone within the well.
  • a method of re-fracturing a subterranean formation penetrated by a well wherein a previously fractured productive zone is isolated from another zone in the well by a temporary blocking gel.
  • the temporary blocking gel is derived from a borated galactomannan gum.
  • a viscosity reducing agent is pumped into the well at a pressure not sufficient to create or enlarge a fracture within the subterranean formation. The viscosity of the temporary blocking gel is reduced.
  • the previously fractured productive zone may then be re-fractured by introducing into the previously fractured productive zone a fracturing fluid at a pressure sufficient to create or enlarge a fracture.
  • a well treatment fluid comprising an unhydrated galactomannan gum is then introduced above the re-fractured productive zone.
  • the re-fractured zone is then isolated by hardening the well treatment fluid.
  • a method of enhancing the productivity of a hydrocarbon-bearing formation penetrated by a well having multiple productive zones is provided.
  • a well treatment fluid comprising a viscosity reducing agent is pumped into a previously fractured productive zone within the well.
  • the previously fractured productive zone is isolated from a second productive zone of the well by a temporary blocking gel derived from a borated galactomannan gum.
  • the viscosity of the temporary blocking agent may then be reduced and the temporary blocking agent removed from the well.
  • the previously fractured productive zone may then be re-fractured by pumping a fracturing fluid into the well at a pressure sufficient to initiate or enlarge a fracture.
  • a well treatment fluid comprising borated galactomannan gum may then be pumped into the well.
  • the re-fractured productive zone may then be isolated from another productive zone within the well by hardening the well treatment fluid comprising the borated galactomannan gum.
  • FIG. 1 illustrates the use of the well treatment fluid in a horizontal well which contains a zonal isolation system.
  • FIG. 2 illustrates the effect of varying levels of pH on the start of gel hydration.
  • FIG. 3 illustrates the effect of a delayer on the start of gel hydration.
  • FIG. 4 illustrates the effect of varying levels of pH with a delayer on the start of gel hydration.
  • FIG. 5 illustrates the effect of varying levels of pH with a delayer on the start of gel hydration.
  • FIG. 6 illustrates the ability of the gel to maintain high viscosity under low shear conditions for isolation.
  • FIG. 7 illustrates the testing conditions used in the Examples. Detailed Description of the Preferred Embodiments
  • the borated galactomannan gum used in the well treatment fluids described herein are galactomannan gums which, prior to being crosslinked or cured, have incorporated borate ions. Such borated galactomannan gums are disclosed in U.S. Patent No. 3,808,195, herein incorporated by reference.
  • the borated polygalactomannan may be prepared by introducing the galactomannan to a material containing a borate ion, i.e., a material which can contribute a borate ion to the reaction.
  • Unhydrated borated galactomannan may be pumped as a powder or as a slurry either in water or in mineral oil added to water.
  • the amount of borated galactomannan pumped into the formation is between from about 100 pounds per thousand gallons of water (ppt) to about 1000 ppt, preferably from about 250 ppt to about 750 ppt.
  • the amount of borated galactomannan in the slurry is between from about 3 pounds per gallon of hydrocarbon to 5 pounds per gallon of hydrocarbon.
  • Preferred galactomannans for use in the invention are guar gum and its derivatives, including natural or underivatized guar, enzyme treated guar gum (having been obtained by treating natural guar gum with galactosidase, mannosidase, or another enzyme) and derivatized guar.
  • the derivatives of polygalactomannans include the water soluble derivatives such as carboxyalkyl ethers, for example, carboxymethyl ether derivatives, hydroxyalkyl ether derivatives such as hydroxyethyl ethers and hydroxypropyl ethers of polygalactomannan, carbamylethyl ethers of polygalactomannan; cationic polygalactomannans and depolymerized polygalactomannans.
  • suitable derivatized guars are those prepared by treating natural guar gum with chemicals to introduce carboxyl groups, hydroxyl alkyl groups, sulfate groups, phosphate groups, etc.
  • Preferred are or a hydroxyalkylated guar (such as hydroxypropyl guar, hydroxyethyl guar, hydroxybutyl guar) or modified hydroxyalkylated guars like carboxylated guars such as carboxy alkylated guars, like carboxy methyl guar as well as carboxylated alkylated hydroxyalkyl guars, such as carboxymethyl hydroxypropyl guar (CMHPG), including those having a molecular weight of about 1 to about 3 million.
  • CMHPG carboxymethyl hydroxypropyl guar
  • the carboxyl content of the such guar derivatives may be expressed as Degree of Substitution ("DS") and ranges from about 0.08 to about 0.18 and the hydroxypropyl content may be expressed as Molar Substitution (MS) (defined as the number of moles of hydroxyalkyl groups per mole of anhydroglucose) and ranges between from about 0.2 to about 0.6.
  • DS Degree of Substitution
  • MS Molar Substitution
  • the borated galactomannan is prepared by soaking polygalactomannan in an alkaline water solution of a material containing borate ions, allowing the polygalactomannan to absorb all of the solution and then milling and drying the polygalactomannan.
  • the amount of water in the alkaline water solution is about equal to the amount of polygalactomannan.
  • the solution is made alkaline with alkali metal or alkaline earth metal hydroxide.
  • the concentration of the alkali metal or alkaline earth metal hydroxide in the solution is about 0.3% to 0.5% by weight based on the weight of the polygalactomannan.
  • the polygalactomannan After the polygalactomannan is absorbed, it is milled and dried at temperature generally between from about 150 °C to about 250° C. to about the original moisture level of untreated polygalactomannan, generally containing about 9% to 12% water by weight. Further processes of preparing the borated polygalactomannan and its derivatives are set forth in U.S. Patent No. 3,808,195.
  • Preferred as the material containing a borate ion are alkali metal, alkaline earth metal and ammonium salts of borate anions.
  • Borate anions include the tetraborate, metaborate and perborate anions.
  • the substituting groups are in a 0.1 molar to 3 molar ratio in the reaction mixtures producing molar substitution of at least 0.1.
  • the molar substitution is the average number of substituting radical substituted per mole of anhydrohexose unit of polygalactomannan gum.
  • concentration of borate ion is expressed as borax, Na 2 B 4 0 7 ⁇ 10H 2 O.
  • Borated guars prepared from the reaction of the borate ion and polygalactomannan gum, are dispersible in water and exhibit a limited ability to be crosslinked when the polygalactomannan is hydrated and the pH of the resulting sol is alkaline. Generally, the polygalactomannan will disperse in water at the same pH level as the untreated polymer. Since the rate of hydration of the borated polygalactomannan is greatest at nearly neutral or acidic pH conditions, the borated polygalactomannan does not hydrate at higher pH values. Because the well treatment fluid is pumped at most only best partially hydrated into the formation, it has a low viscosity which minimizes friction pressures and which allows placement of the well treatment fluid, such as at low pump rates or with coiled tubing.
  • viscosity of the well treatment fluid may be controlled and maintained at a desired temperature.
  • Suitable pH adjustment agents include soda ash, potassium hydroxide, sodium hydroxide and alkaline and alkali carbonates and bicarbonates, may be used to maintained the desired pH.
  • Typical the desired pH for hardening of the well treatment fluid is greater than 8.0, more preferably greater than 9.0.
  • the well treatment fluid is therefore highly effective in preferentially sealing or blocking productive zones in the formation since delayed hydration of the fluid may be controlled for up to several hours by the amount of borate used on the guar or guar derivative, as well as the pH of the system.
  • the viscosity of the fluid may be decreased, typically by use of pH or temperature controlled breakers, when the passive isolation of the zones is no longer desired.
  • crosslinking of the borated polygalactomannan may further be delayed to high temperatures, for example, up to 120° F; and often to as high as 350° F.
  • the crosslinking agent used in the fluid of the invention is typically a delayed crosslinking agent (in order to delay hydration of the polygalactomannan), though other crosslinking agents may be used. In many instances, hydration may be controlled for up to 24 to 36 hours prior to forming a gel of sufficient viscosity to function as a sealant.
  • the crosslinking agent is borax. In addition to borax other borate ion releasing compounds may be used as well as organometallic or organic complexed metal ions comprising at least one transition metal or alkaline earth metal ion as well as mixtures thereof.
  • Borate ion releasing compounds which can be employed include, for example, any boron compound which will supply borate ions in the composition, for example, boric acid, alkali metal borates such as sodium diborate, potassium tetraborate, sodium tetraborate (borax), pentaborates and the like and alkaline and zinc metal borates.
  • borate ion releasing compounds are disclosed in U.S. Pat. 3,058,909 and U.S. Pat. No3,974,077 herein incorporated by reference.
  • borate ion releasing compounds include boric oxide (such as selected from H 3 BO 3 and B 2 O 3 ) and polymeric borate compounds.
  • a suitable polymeric borate compound is a polymeric compound of boric acid and an alkali borate which is commercially available under the trademark POLYBOR® from U.S. Borax of Valencia, Calif. Mixtures of any of the referenced borate ion releasing compounds may further be employed. Such borate-releasers typically require a basic pH (e.g., 8.0 to 12) for crosslinking to occur.
  • a basic pH e.g., 8.0 to 12
  • crosslinking agents are reagents, such as organometallic and organic complexed metal compounds, which can supply zirconium IV ions such as, for example, zirconium lactate, zirconium lactate triethanolamine, zirconium carbonate, zirconium acetylacetonate and zirconium diisopropylamine lactate; as well as compounds that can supply titanium IV ions such as, for example, titanium ammonium lactate, titanium triethanolamine, and titanium acetylacetonate.
  • Zr (IV) and Ti (IV) may further be added directly as ions or oxy ions into the composition.
  • Such organometallic and organic complexed metal crosslinking agents containing titanium or zirconium in a +4 valence state include those disclosed in British Pat. No. 2,108,122, herein incorporated herein by reference, which are prepared by reacting zirconium tetraalkoxides with alkanolamines under essentially anhydrous conditions.
  • Other zirconium and titanium crosslinking agents are described, for example, in U.S. Pat. No. 3,888,312; U.S. Pat. No. 3,301,723; U.S. Pat. No. 4,460,751; U.S. Pat. No. 4,477,360; Europe Pat. No. 92,755; and U.S. Patent No.
  • Such organometallic and organic complexed metal crosslinking agents containing titanium or zirconium in a +4 oxidation valance state may contain one or more alkanolamine ligands such as ethanolamine (mono-, di- or triethanolamine) ligands, such as bis(triethanolamine)bis(isopropyl)-titanium (IV). Further, the compounds may be supplied as inorganic oxides, such as zirconium or titanium dioxide.
  • Such crosslinking agents are typically used at a pH also in the range from about 6 to about 13.
  • crosslinking metal ion, metal containing species, or mixture of such ions and species may further be employed.
  • the crosslinking agent for use in the thermal insulating composition of the invention are reagents capable of providing Zn (II), calcium, magnesium, aluminum, Fe (II), and Fe (III) to the composition. These may be applied directly to the composition as ions or as polyvalent metallic compounds such as hydroxides and chlorides from which the ions may be released.
  • the crosslinking ions or species may be provided, as indicated, by dissolving into the solution compounds containing the appropriate metals or the metal ion per se.
  • concentration of crosslinking agent is dependent on factors such as polymer concentration and the temperature in the annuli and will normally range from about 5 ppm to about 2000 ppm, preferably from about 100 ppm to about 900 ppm. It is an important advantage of the invention that higher levels of the crosslinking metal ion or metal containing species may be employed, thereby insuring improved crosslinking.
  • Well treatment fluids containing the borated galactomannan gum have particular applicability in the treatment of formations where multiple productive zones are known to be present. For instance, in certain formations, such as shale, it may be desired to frac the formation in numerous stages, between from 6 to 40 stages.
  • the well treatment fluid may function as an isolation system for several hours up to several days.
  • the treatment fluid may be used in vertical as well as non- vertical wells, most notably horizontal wells.
  • the well treatment fluid has particular applicability for use as passive chemical annular isolation systems to isolate zones of interest for stimulation.
  • the fluid may be introduced into a well having a casing lining or into an open hole.
  • the well treatment fluid defined herein has particular applicability when used in conjunction with a mechanical zonal isolation system. In such methods, it is usually desired to perforate and fracture the isolated zone without the use of any cement.
  • a horizontal well 10 penetrating formation 12 and having surface casing 15 and intermediary string 20 is equipped with piping 25 and mechanical zonal isolation assembly 30.
  • the well treatment fluid 27 is introduced into the wellbore and fills the space between piping 25 and casing 15.
  • string 20 at a desired location is perforated and formation 12 then is subjected to hydraulic fracturing wherein fractures 40 are created. After fracturing is completed, viscosity of the fluid is broken by interaction of a breaker.
  • intermediary string 20, piping 25 and mechanical zonal isolation assembly 30 may further be removed from the well.
  • a productive zone of a well having multiple productive zones may be first perforated.
  • a fracturing fluid may then be introduced into the perforated productive zone at a pressure sufficient to fracture the perforated productive zone.
  • the well treatment fluid defined herein may then be introduced into the fractured perforated productive zone.
  • the perforated productive zone may then be isolated by hardening the well treatment fluid.
  • another productive zone of the well may be perforated and the process repeated. This procedure is typically done by cementing a vertical well to the annulus prior to perforation of the first zone.
  • one or more of the productive zones may contain a zonal isolation assembly as previously described.
  • the well treatment fluid described herein may be introduced into a pre-determined productive zone of a well containing multiple productive zones.
  • the fluid in the pre-determined productive zone is then hardened, thereby isolating the pre-determined productive zone from the other zones of the well.
  • the zone may then be perforated the zone may then be subjected to hydraulic fracturing since the zone of interest is sealed from other zones.
  • the treatment fluid may further be used in a method which also uses a mechanical device, such as a packer, plug or sand fill.
  • a mechanical device such as a packer, plug or sand fill.
  • Such mechanical devices may be first set in the well between a zone to be fractured and an adjacent zone of the well. This method is more practical for use in non- vertical wells.
  • a zonal isolation assembly unit may be present in one or more of the zones to be fractured, the area defined by the two packers containing the zonal isolation assembly unit.
  • the well treatment fluid defined herein may then be introduced into the well.
  • the area between the first and second packers is sealed off of other zones within the well.
  • the sealed area may then be subjected to fracturing.
  • the process may then be repeated over successive periods in order to fracture other zones of interest within the well.
  • any zonal isolation system may be removed from the well.
  • the well treatment fluid further minimizes cementing of natural fractures.
  • cement As an alternative to cement, the well treatment fluid defined herein may be used in place of, or in addition to, cement.
  • a fluid containing a slurry of the borated galactomannan may be introduced into a slurry of the fluid may be introduced into the annulus of the well between a wall of the wellbore and a pipe string disposed in the wellbore.
  • the pipe string has disposed therein a zonal isolation assembly.
  • an isolated productive zone within the zonal isolation assembly may then be perforated.
  • the zonal isolation assembly may be multi-interval fracture treatment isolation assembly, such as that known in the prior art, including that type of assembly disclosed in U.S. Patent No. 6,386,288.
  • the well may then be subject to hydraulic fracturing at a pressure which is sufficient to fracture the isolated productive zone.
  • the well may be a non-vertical well.
  • the well contains only tubing and does not contain a casing.
  • the mechanical isolation assembly is joined to the tubing.
  • the fluid provides passive zonal isolation in that the borated galactomannan may be removed from the well by breaking of the gel.
  • the fluid may therefore be used in place of a mechanical packer.
  • the passive zonal isolation methods described herein therefore provide for annular isolation, like conventional cements, without damaging the formation.
  • the annular isolation system provided by the crosslinked gel exits the well during post job flow-back operations, leaving the formation face virtually damage free for post frac production.
  • the well treatment fluids defined herein are particularly effective in those applications where re-fracturing the formation may be ultimately desired.
  • a seal containing the borated galactomannan gum may be broken and the borated galactomannan gum removed from the well by introducing into the well a viscosity reducing agent.
  • the viscosity reducing agent at least partially degrades the gelled borated galactomannan gum and the borated galactomannan gum becomes less viscous and thus removable from the well.
  • seals which isolate a fractured productive zone from another zone within the formation with a borated galactomannan gum as defined herein may be removed from the well such that the formerly isolated productive zone may be subjected again to a fracturing operation.
  • the fluid containing the viscosity reducing agent is pumped into the well at a pressure which is insufficient to create or enlarge a fracture within the formation.
  • a fracturing fluid may be pumped into the well at a pressure sufficient to create or enlarge a fracture within the formation. In this manner, a previously fractured productive zone within the formation may be subjected to hydraulic fracturing.
  • the formation is re-fractured by pumping the fracturing fluid into a pre-determined productive zone of a well that has been previously fractured or was attempted to be fractured and which contains multiple productive zones.
  • a location of a formation of a multizone wellbore may be re-fractured by hydraulically isolating a first location from a portion of the multizone wellbore uphole from the first location, the first location having been previously hydraulically fractured at least once and hydraulically re-fracturing the first location.
  • a well treatment fluid containing an unhydrated galactomannan gum may be introduced into the well as described herein and the re- fractured zone isolated by hardening the well treatment fluid.
  • the method of re-fracturing may consist of multiple re-fracturing operations wherein a fluid containing the viscosity reducing agent is introduced into the well and the temporary seal blocking a productive zone from another zone within the formation is removed, the formation is subjected to fracturing, a fluid containing the borated galactomannan gum is introduced into the well and hardened to isolate the re-fractured productive zone from other productive zones within the formation and the process then repeated.
  • Suitable viscosity reducing agents include any material(s) suitable for imparting viscosity reduction characteristics to the borated galactomannan gum fluid.
  • suitable materials include, but are not limited to, oxidizing agents (such as sodium bromate), amines, acids, acid salts, acid-producing materials, enzyme breakers, encapsulated breakers, etc., and combinations thereof.
  • the viscosity reducing agents facilitate the degradation of the borated galactomannan gum in the well treatment fluid, whereby the degraded fluid may be removed from the subterranean formation to the well surface.
  • Suitable acids include hydrochloric acid, formic acid or sulfamic acid as well as acid salts, such as sodium bisulfate.
  • Suitable oxidizing agents include alkaline earth and metal peroxides (like magnesium peroxide, calcium peroxide and zinc peroxide), organic peroxides, hydrochlorite bleaches, persulfate salts (used either as is or encapsulated) such as ammonium persulfate, sodium persulfate, ammonium peroxydisulfate and potassium persulfate, chromous salts, sodium bromate, sodium perchlorate, sodium perborate, magnesium perborate, calcium perborate, etc.
  • Enzyme breakers capable of breaking the backbone of the crosslinked gel into monosaccharide and disaccharide fragments, such as galactomannases, may also be used.
  • the viscosity reducing agent is introduced into the well in an amount sufficient to at least partially degrade the borated galactomannan gum such that the temporary seal isolating the previously fractured productive zone may be removed.
  • Polymer refers to borated guar, commercially available from Baker Hughes Incorporated as GW-26.
  • Borax is used as the delay hydration additive (which also acts as a cross- linking agent).
  • GBW-25 a breaker, is sodium bromate, commercially available from Baker Hughes Incorporated. Viscosity was measured using a Chandler high pressure high temperature (HPHT) 5550 viscometer.
  • HPHT Chandler high pressure high temperature
  • Example 1 The effect of varying levels of pH on the start of gel hydration was tested using viscosity measurements. The results are set forth in FIG. 2.
  • the gel was created using 100 ppt Polymer in water. This slurry had a pH of 8.84. The pH was increased with a sodium hydroxide solution (10% by weight in water) to values of 9.5, 9.75 and 10.1. The slurry was loaded in to the viscometer and viscosity measured at a shear rate of 100 sec-1. The temperature of the viscometer was ramped from 70°F to 250°F in two hours and was then kept constant at 250°F for an additional hour.
  • FIG. 2 demonstrates that pH affects the viscosity in the following manner:
  • FIG. 2 further shows that the start time of hydration may be controlled by pH.
  • Example 2 Using the above procedure, the effect of adding borax as a delayer while maintaining a pH of 9.5 was examined. The results are set forth in FIG. 3. For each run, the gel was created using 100 ppt Polymer in water and sodium hydroxide solution to adjust the pH. Borax was added in 1%, 2%, 3% by weight of Polymer as a delaying agent. The slurry was loaded in to the viscometer and viscosity measured at a shear rate of 100 sec-1. The temperature of the viscometer was ramped from 70° F to 250° F in two hours and was then kept constant at 250° F for an additional hour. The results show that borax by itself (without any pH adjustment) did little to delay hydration, however, when coupled with an increase of pH from 8.84 to 9.5, made a significant difference in slowing the hydration rate. Specifically:
  • Example 1 the gel was adjusted to a pH of 9.5 from Example 1 was also included in FIG. 3. It is clear that the addition of a delayer along with an increase of pH to 9.5 enables a greater control of the time hydration starts.
  • Example 3 The effect of pH and delayer on hydration time was examined and the results are set forth in FIG. 4.
  • the gel was created using 100 ppt Polymer in water. This slurry had a pH of 8.84. The pH to lower values was obtained by adding acetic acid until pH values of 8.5 and 8.75 were obtained. The pH to higher levels was obtained by the addition of a sodium hydroxide solution (10% by weight in water) to pH values of 9 and 9.2. The slurry was loaded in to the viscometer and viscosity measured at a shear rate of 100 sec "1 . The temperature of the viscometer was ramped from 70°F to 100°F in 30 minutes and was then kept constant at 100°F for an additional 90 minutes. In some of the runs, borax was added as a delayer. The results show that hydration time can be changed with changes in pH. Specifically:
  • Example 4 Using the above procedure, the effect of both pH and delayer on hydration time was examined.
  • the gel was created using 100 ppt Polymer in water. This slurry had a pH of 8.84. The pH was increased with sodium hydroxide solution (10%> by weight in water) to 9 and 9.25. The slurry was loaded in to the viscometer and viscosity measured at a shear rate of 100 sec "1 . The temperature of the viscometer was ramped from 70°F to 150°F in 30 minutes and was then kept constant at 150°F for an additional 90 minutes. The results show that hydration time can be changed with changes in both delayer concentration and pH. Specifically, the onset of hydration time varied from 35 minutes to 90 minutes, a greater variation than was shown in Example 3.
  • Example 5 Using the above procedure, the optimum result of the above examples (3% borax and pH of 9.65) was further examined to determine if high viscosity for isolation could be achieved. The results are set forth in FIG. 6.
  • the gel was created using 500 ppt Polymer in water, 10% sodium hydroxide solution to adjust the pH and borax to act as a delayer. The slurry was loaded in to the viscometer and viscosity measured at a shear rate of 100 sec "1 . The temperature of the viscometer was ramped from 70°F to 250°F in two hours and was then kept constant at 250°F for an additional 6 hours.
  • Example 6 The ability of a gel to be pumped into a horizontal position and to be held at differential pressure was determined by use of two high pressure fluid loss cells (about eight inches in length and two inches in diameter), one positioned horizontally and one vertically. These cells were positioned as illustrated in FIG. 7.
  • the horizontal cell 50 which will contain the temporary blocking gel, has the addition of either a slotted insert 60a or a ⁇ 1 md ceramic core 60b at the end 70 of the cell.
  • the slotted insert simulates a formation with perforation.
  • the ceramic core simulates formation without perforation. Unless specifically stated in the example, the default is the slotted insert.
  • jack 65 was used to raise or lower the horizontal cell to a desired angle.
  • Tubing 75 connected the bottom of vertical cell 55 with the side of horizontal cell 50.
  • Tubing 75 simulates the heel of the wellbore.
  • a heater was placed around the horizontal cell to heat and control temperature.
  • a temperature ramp was used to elevate the temperature of the gel in the horizontal cell.
  • the gel was pumped from the vertical cell 55 to the horizontal cell as a slurry in tap water via tubing and pressured to 100 psi. After pumping the gel into horizontal cell 50 and allowing a two hour residence time at temperature to crosslink the gel, vertical cell 55 was filled with dyed tap water. Additional pressure was then applied to the top of the vertical cell and the volume of water lost from the vertical cell to the horizontal cell was used as the measure of isolation. In addition, the amount of gel extruded through the slotted insert was also measured.
  • Example 7 illustrates the ability of the well treatment fluid of the invention to act as a block for a period of time at pressure duplicating formation with no perforation.
  • the test procedure was to create a composition of the gel used in Example 5 (500 ppt Polymer and water with 3% borax by weight of Polymer buffered to a pH of 9.65 with the addition of 10% sodium hydroxide solution).
  • the protocol was the same as with Example 6 with the exception of a ⁇ 1MD ceramic core was used.
  • the gel was pumped from the vertical cell to the horizontal cell and allowed to heat up to 250 F for two hours at 100 psi to crosslink the gel.
  • the vertical cell was filled with dyed tap water.
  • Example 8 illustrates the ability to pump a stimulation fluid through the blocking gel in a formation with perforation.
  • the test procedure was to create a composition of the gel used in Example 5 (500 ppt Polymer and water with 3% borax by weight of Polymer buffered to a pH of 9.65 with the addition of 10% sodium hydroxide solution).
  • the protocol was the same as Example 6 with the slotted insert simulating perforation.
  • the gel was pumped from the vertical cell to the horizontal cell and allowed to heat up to 250 F for two hours at 100 psi to crosslink the gel.
  • the vertical cell was filled with dyed tap water. When pressure was increased, there was water breakthrough at 125 psi - a water channel was created through the gel near the center of the gel pack. This example indicates that a stimulation fluid can be successfully pumped through the blocking gel to a formation with a perforation.
  • Example 9 A series of tests was designed to evaluate how to break the gel, once its utility as a blocker was over. The results are set forth in Tables 1 and 2. These tests used two different breakers in various concentrations. The test procedure was to create a composition of the gel used in Example 5 (500 ppt Polymer and water with 3% borax by weight of Polymer buffered to a pH of 9.65 with the addition of 10% sodium hydroxide solution). The breakers as described in the tables 1 and 2 were added to the gels. 400 mL of the gels were then placed in the horizontal fluid loss cell as described before and heated to indicated temperature at 1000 psi. The cells were opened periodically to see if the gels were broken. Table 1 shows results using the GBW-25, as breaker, and Table 2 shows results using the breaker High Perm CRB (encapsulated ammonium persulfate)

Landscapes

  • Chemical & Material Sciences (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Materials Engineering (AREA)
  • Organic Chemistry (AREA)
  • Mining & Mineral Resources (AREA)
  • Geology (AREA)
  • Fluid Mechanics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Physics & Mathematics (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Ceramic Engineering (AREA)
  • Structural Engineering (AREA)
  • Lubricants (AREA)
  • Curing Cements, Concrete, And Artificial Stone (AREA)
  • Compositions Of Macromolecular Compounds (AREA)

Abstract

L'invention concerne un fluide de traitement de puits contenant un galactomannane boré pouvant être utilisé pour isoler une zone productrice dans un puits présentant de multiple zones productrices. Le fluide est particulièrement utile dans le traitement des puits contenant un système mécanique d'isolement par zone dans la zone productrice d'intérêt. Le fluide est pompé dans le puits sous une forme sensiblement non hydratée. Le fluide de traitement de puits est donc très efficace pour le scellage ou le blocage préférentiel de zones productrices dans la formation étant donné qu'une hydratation retardée du fluide peut être commandée pendant plusieurs heures. Le joint peut être dégradé et une zone productrice peut être soumise à une re-fracturation par l'introduction d'un agent de réduction de viscosité dans le puits.
PCT/US2014/071566 2014-01-27 2014-12-19 Procédé de re-fracturation au moyen de gomme de galactomannane borée WO2015112297A1 (fr)

Priority Applications (3)

Application Number Priority Date Filing Date Title
CN201480074326.7A CN106133111A (zh) 2014-01-27 2014-12-19 使用硼酸化的半乳甘露聚糖胶重复压裂的方法
CA2938037A CA2938037C (fr) 2014-01-27 2014-12-19 Procede de re-fracturation au moyen de gomme de galactomannane boree
RU2016134934A RU2682833C2 (ru) 2014-01-27 2014-12-19 Способ проведения повторного гидравлического разрыва пласта с использованием борированной галактоманнановой камеди

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US14/165,427 US9920609B2 (en) 2010-03-12 2014-01-27 Method of re-fracturing using borated galactomannan gum
US14/165,427 2014-01-27

Publications (1)

Publication Number Publication Date
WO2015112297A1 true WO2015112297A1 (fr) 2015-07-30

Family

ID=52424105

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2014/071566 WO2015112297A1 (fr) 2014-01-27 2014-12-19 Procédé de re-fracturation au moyen de gomme de galactomannane borée

Country Status (4)

Country Link
CN (1) CN106133111A (fr)
CA (1) CA2938037C (fr)
RU (1) RU2682833C2 (fr)
WO (1) WO2015112297A1 (fr)

Families Citing this family (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN107605452A (zh) * 2017-09-29 2018-01-19 中国石油天然气股份有限公司 一种水平井重复压裂方法
RU2737630C1 (ru) * 2019-12-10 2020-12-01 Публичное акционерное общество "Славнефть-Мегионнефтегаз" Способ проведения повторного многостадийного гидравлического разрыва пласта в горизонтальной скважине

Citations (16)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2868664A (en) * 1954-05-03 1959-01-13 Stein Hall & Co Inc Dry mannogalactan composition
US3058909A (en) 1957-07-23 1962-10-16 Atlantic Refining Co Method and composition for formation fracturing
US3301723A (en) 1964-02-06 1967-01-31 Du Pont Gelled compositions containing galactomannan gums
US3766984A (en) * 1968-05-20 1973-10-23 Dow Chemical Co Method for temporarily sealing a permeable formation
US3808195A (en) 1972-04-14 1974-04-30 Gen Mills Chem Inc Process for preparing dispersible polygalactomannan gum and derivatives
US3888312A (en) 1974-04-29 1975-06-10 Halliburton Co Method and compositions for fracturing well formations
US3974077A (en) 1974-09-19 1976-08-10 The Dow Chemical Company Fracturing subterranean formation
GB2108122A (en) 1981-10-29 1983-05-11 Dow Chemical Co Zirconium crosslinkers for solvatable polysaccharide solutions
EP0092755A1 (fr) 1982-04-22 1983-11-02 KAY-FRIES, Inc. Zirconates bisalcoyl-bis(trialcoylamine)
US4460751A (en) 1983-08-23 1984-07-17 Halliburton Company Crosslinking composition and method of preparation
US4477360A (en) 1983-06-13 1984-10-16 Halliburton Company Method and compositions for fracturing subterranean formations
US4780223A (en) 1985-07-08 1988-10-25 Dowell Schlumberger Incorporated Stabilized fracture fluid and crosslinker therefor
US6386288B1 (en) 1999-04-27 2002-05-14 Marathon Oil Company Casing conveyed perforating process and apparatus
US7575062B2 (en) 2006-06-09 2009-08-18 Halliburton Energy Services, Inc. Methods and devices for treating multiple-interval well bores
US20110220363A1 (en) * 2010-03-12 2011-09-15 Gupta D V Satyarnarayana Method of Treating a Wellbore Having Annular Isolation System
US8486867B2 (en) * 2009-10-15 2013-07-16 Baker Hughes Incorporated Method of fracturing using mannanohydrolase enzyme breaker

Family Cites Families (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6814145B2 (en) * 2001-08-02 2004-11-09 Schlumberger Technology Corporation Shear-sensitive plugging fluid for plugging and a method for plugging a subterranean formation zone
US20060009363A1 (en) * 2001-11-13 2006-01-12 Baker Hughes Incorporated Deep water completions fracturing fluid compositions
US6936575B2 (en) * 2002-10-07 2005-08-30 Texas United Chemical Company, Llc. Borate crosslinker suspensions with more consistent crosslink times
US7703527B2 (en) * 2007-11-26 2010-04-27 Schlumberger Technology Corporation Aqueous two-phase emulsion gel systems for zone isolation
US20100096129A1 (en) * 2008-10-17 2010-04-22 Schlumberger Technology Corporation Method of hydrocarbon recovery

Patent Citations (16)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2868664A (en) * 1954-05-03 1959-01-13 Stein Hall & Co Inc Dry mannogalactan composition
US3058909A (en) 1957-07-23 1962-10-16 Atlantic Refining Co Method and composition for formation fracturing
US3301723A (en) 1964-02-06 1967-01-31 Du Pont Gelled compositions containing galactomannan gums
US3766984A (en) * 1968-05-20 1973-10-23 Dow Chemical Co Method for temporarily sealing a permeable formation
US3808195A (en) 1972-04-14 1974-04-30 Gen Mills Chem Inc Process for preparing dispersible polygalactomannan gum and derivatives
US3888312A (en) 1974-04-29 1975-06-10 Halliburton Co Method and compositions for fracturing well formations
US3974077A (en) 1974-09-19 1976-08-10 The Dow Chemical Company Fracturing subterranean formation
GB2108122A (en) 1981-10-29 1983-05-11 Dow Chemical Co Zirconium crosslinkers for solvatable polysaccharide solutions
EP0092755A1 (fr) 1982-04-22 1983-11-02 KAY-FRIES, Inc. Zirconates bisalcoyl-bis(trialcoylamine)
US4477360A (en) 1983-06-13 1984-10-16 Halliburton Company Method and compositions for fracturing subterranean formations
US4460751A (en) 1983-08-23 1984-07-17 Halliburton Company Crosslinking composition and method of preparation
US4780223A (en) 1985-07-08 1988-10-25 Dowell Schlumberger Incorporated Stabilized fracture fluid and crosslinker therefor
US6386288B1 (en) 1999-04-27 2002-05-14 Marathon Oil Company Casing conveyed perforating process and apparatus
US7575062B2 (en) 2006-06-09 2009-08-18 Halliburton Energy Services, Inc. Methods and devices for treating multiple-interval well bores
US8486867B2 (en) * 2009-10-15 2013-07-16 Baker Hughes Incorporated Method of fracturing using mannanohydrolase enzyme breaker
US20110220363A1 (en) * 2010-03-12 2011-09-15 Gupta D V Satyarnarayana Method of Treating a Wellbore Having Annular Isolation System

Also Published As

Publication number Publication date
CN106133111A (zh) 2016-11-16
RU2682833C2 (ru) 2019-03-21
RU2016134934A3 (fr) 2018-07-26
RU2016134934A (ru) 2018-03-05
CA2938037A1 (fr) 2015-07-30
CA2938037C (fr) 2018-01-23

Similar Documents

Publication Publication Date Title
US9920609B2 (en) Method of re-fracturing using borated galactomannan gum
CA2790840C (fr) Procede de traitement d'un trou de forage dote d'un systeme d'isolation annulaire
US10989011B2 (en) Well intervention method using a chemical barrier
US9175208B2 (en) Compositions and methods for breaking hydraulic fracturing fluids
CA2323007C (fr) Compositions a viscosite modifiee et methodes pour le traitement des puits
US20170335172A1 (en) Aldehydes as a catalyst for an oxidative breaker
WO2007066254A2 (fr) Deviation ou isolation assistee par un materiau degradable
US20190309217A1 (en) Amaranth grain particulates for diversion applications
CA2938037C (fr) Procede de re-fracturation au moyen de gomme de galactomannane boree
US9909056B2 (en) Method of altering crosslink time of delayed borate crosslinkers
US10989035B2 (en) Proppant ramp-up for cluster efficiency
CA2999255C (fr) Utilisation de particules de qualite alimentaire pour former des fractures ayant une conductivite et une porosite accrues
WO2018080437A1 (fr) Procédés de dérivation et de commande de perte de fluide à l'aide de compositions de saumure de formiate

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 14830921

Country of ref document: EP

Kind code of ref document: A1

ENP Entry into the national phase

Ref document number: 2938037

Country of ref document: CA

NENP Non-entry into the national phase

Ref country code: DE

ENP Entry into the national phase

Ref document number: 2016134934

Country of ref document: RU

Kind code of ref document: A

122 Ep: pct application non-entry in european phase

Ref document number: 14830921

Country of ref document: EP

Kind code of ref document: A1